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Riviera Resources Reports Third-Quarter 2019 Results and Announces Sale of East Texas Overton Properties for $18.5 Million


Source: Riviera Resources, Inc.

HOUSTON, Nov. 07, 2019 (GLOBE NEWSWIRE) — Riviera Resources, Inc. (OTCQX: RVRA) (“Riviera” or the “Company”) and its wholly owned subsidiary, Blue Mountain Midstream LLC (“Blue Mountain”) announces financial and operating results for the third quarter 2019.

The Company highlights the following accomplishments:

  • Increased previously announced $100 million share repurchase authorization to a total of $150 million
  • Returned over $140 million of capital to shareholders through share repurchases and tender offer since the beginning of the year, and over $295 million since August 2018
  • Signed definitive agreements to sell our remaining Hugoton Basin assets for a contract price of $295 million, and interests in properties located in the Overton field of East Texas for a contract price of $18.5 million
  • Ended the third quarter with a consolidated cash balance of ~$83 million and ~$61 million drawn on the Blue Mountain Credit Facility
  • Averaged approximately 242 MMcfe/d of production in the third quarter, in line with our guidance range
  • Invested Upstream capital of approximately $6 million, ~33% below the guidance target for the quarter

Blue Mountain highlights:

  • Entered into a long-term, fee-based crude oil gathering agreement with Roan Resources, Inc. (“Roan”) and construction commenced on initial facilities for the North and South systems
  • Roan entered into an agreement and plan of merger with Citizen Energy Operating, LLC (“Citizen”), which is a portfolio company of Warburg Pincus
  • Placed into service water gathering pipelines, connecting to 14 Roan pads
  • Closed the acquisition of Lumen Midstream Partnership, LLC, and constructed interconnect facilities, with volumes redirected to the cryo plant beginning on October 1, 2019
  • Continued engagement with Tudor, Pickering, Holt & Co. to review strategic alternatives to unlock unrealized value

David Rottino, Riviera’s President and Chief Executive Officer, commented, “I am very pleased with Riviera’s performance in the third quarter. We remain relentlessly focused on our commitment to maximizing shareholder value through our strategy of capital discipline, returning capital to shareholders and efficiently managing our assets. So far this year, we have generated approximately $220 million in proceeds through opportunistic asset monetizations, and returned over $140 million of capital to shareholders through our ongoing share repurchase program and July tender offer. In addition, we will generate significant proceeds from the sale of our remaining Hugoton assets that we still expect to close in the fourth quarter of this year that can be used to return capital to shareholders. Finally, we continue to work with Tudor, Pickering, Holt & Co. to review strategic alternatives for our Blue Mountain midstream business.”

Key Financial Results (1)
  Three Months Ended Nine Months Ended
  September 30,   September 30,
$ in millions 2019 2018   2019 2018
Average daily production (MMcfe/d) 242 302 264 338
Total oil, natural gas and NGL revenues $ 51 $ 90 $ 194 $ 314
(Loss) income from continuing operations $ (226) ($ 33) $ (220) $ 10
(Loss) income from discontinued operations, net of income taxes $ ­­- ($ 15) $ ­­- $ 20
Net (loss) income $ (226) ($ 48) $ (220) $ 30
Adjusted EBITDAX (a non-GAAP financial measure) (2) $ 21 $ 12 $ 84 $ 63
Net cash provided by (used in) operating activities $ 29 ($ 85) $ 88 $ (28)
Oil and natural gas capital $ 6 $ 7 $ 60 $ 24
Total capital (3) $ 42 $ 34 $ 144 $ 143
(1) All amounts reflect continuing operations with the exception of net (loss) income for the three months and nine months ended September 30, 2018.
(2) Includes severance costs of approximately $2 million and success fee on capital reimbursement agreement of approximately $2 million for both the three months and nine months ended September 30, 2019, and severance costs of approximately $8 million and $26 million for the three months and nine months ended September 30, 2018, respectively.
(3) Includes approximately $3 million of capital for the Lumen acquisition for both the three months and nine months ended September 30, 2019.

Opportunistic Asset Monetizations
Thus far in 2019, the Company has closed six transactions that in combination generated proceeds of approximately $220 million. The six transactions include the sale of the Arkoma Basin assets (closed January 2019), the monetization of a portion of the Company’s helium reserves in the Hugoton Basin utilizing a VPP structure (closed March 2019), the sale of certain non-operated properties located in the Hugoton Basin (closed May 2019), the sale of properties located in Michigan (closed July 2019), the sale of certain non-core properties located in North Louisiana (closed August 2019), and the sale of properties located in Illinois (closed September 2019).

The Company has also signed definitive agreements to sell its remaining interests in properties located in the Hugoton Basin, expected to close in the fourth quarter of 2019, and its interest in properties located in the Overton field in East Texas, that is expected to close in the first quarter of 2020. In combination, the transactions are expected to generate estimated proceeds of approximately $300 million. The Board and management will determine the use of proceeds, which consistent with past history may include a significant return of capital to shareholders.

Continuation of Share Repurchase Plan
The Company has returned over $140 million of capital to shareholders through a tender offer and share repurchases since the beginning of the year, and over $295 million since August 2018.

On July 18, 2019, the Board increased the share repurchase authorization to $150 million of the Company’s outstanding shares of common stock. Through September 30, 2019, the Company repurchased an aggregate of 8,916,526 shares at an average price of $13.55 for a total cost of approximately $121 million. In the third quarter alone the Company bought back 2,327,416 shares at an average price of $10.70 for a total cost of approximately $25 million. As of October 31, 2019, approximately $28 million was available for share repurchase under the program.

Third Quarter 2019 Activity – Upstream Assets
The Company performed in line with expectations in the third quarter with respect to its upstream assets. Production for the third quarter averaged approximately 242 MMcfe/d, in line with our guidance range. Upstream capital expenditures were approximately $6 million, 33% below the guidance target for the quarter. Adjusted G&A expenses were approximately $9 million, and operating expenses were approximately $39 million, both in-line with guidance ranges for the quarter.

Blue Mountain Business Update
In the third quarter of 2019, natural gas throughput averaged 114 MMcf/d and NGLs produced were 7,250 bpd. Average natural gas throughput for the nine months ending September 30, 2019 was 117 MMcf/d. During the third quarter, 13 wells were turned to sales on the Blue Mountain system; however, throughput volumes were impacted due to our primary customer Roan preloading or temporarily shutting-in 15 producing wells during the quarter, contributing to an average throughput loss on the system of ~11 MMcf/d since the second quarter of 2019. We anticipate these wells and volumes to return in the fourth quarter of 2019 and the first quarter of 2020.

Management expects throughput volumes from its primary customer to remain relatively flat during the remainder of 2019 as Roan recently entered into an agreement and plan of merger with Citizen. Roan has significantly curtailed operations pending the closing of that transaction, which is anticipated to take place prior to yearend. Citizen is a portfolio company of Warburg Pincus, which has over $62 billion of assets under management and substantial experience in the energy sector.

On August 5, 2019, Blue Mountain acquired 100% interests in Lumen Midstream Partnership, LLC, including approximately 55 miles of natural gas gathering pipelines and an 18 MMcf/d processing plant. During the quarter, the Lumen system was connected to the Blue Mountain system, adding natural gas throughput of ~5 MMcf/d at the cryo plant, beginning on October 1, 2019.

Blue Mountain began gathering produced water on pipelines for Roan in July 2019, averaging 8,280 bpd during the third quarter of 2019. As the company progresses on the buildout of its water gathering system, it continues to transport produced water via third-party trucking services, hauling 5 million barrels of water in total, or averaging 54,165 bpd, during the third quarter of 2019. In September 2019, Blue Mountain executed a new water services agreement with a large independent producer. The agreement includes a minimum volume commitment of 5,000 bpd over a three-year term, with facilities estimated in-service in November 2019. In addition, Blue Mountain has placed in-service its first owned and operated disposal well and is constructing two more water disposal facilities, one of which is estimated to be in-service in the fourth quarter of 2019. Furthermore, Blue Mountain has acquired additional disposal capacity through a non-operated interest in another well that went in service in October 2019.

Blue Mountain entered into a crude oil gathering agreement with Roan Resources in July 2019. Construction has commenced on the initial facilities consisting of approximately 50 miles of gathering pipelines across the North and South systems, with an estimated in-service date in the first half of 2020.

During the quarter, the business was impacted by lower throughput volumes and overall lower commodity prices. Also, the business continued to be impacted by the NGL pricing differentials at Conway and Mont Belvieu, along with ineffective hedges related to these pricing differences. As a result, Blue Mountain’s third quarter adjusted EBITDA decreased by approximately $5 million compared with second quarter results. The elimination of the impact of the hedges would have added approximately $3 million to Blue Mountain’s Adjusted EBITDA. Management expects to eliminate all basis dislocation in the first quarter of 2020 when ONEOK’s Arbuckle II Pipeline is completed.

Capital expenditures for the third quarter were approximately $36 million (including approximately $3 million of acquisition capital), with the majority of capital being invested in the construction of water gathering pipelines.

Balance Sheet and Liquidity
Riviera and Blue Mountain have established separate credit facilities. As of September 30, 2019, there were no borrowings outstanding on Riviera’s revolving credit facility, and borrowing commitments of up to $90 million with available borrowing capacity of approximately $57 million, inclusive of outstanding letters of credit. At quarter end, Riviera had approximately $62 million of cash. In September 2019, Riviera amended its Credit Facility. The amendment resulted in a borrowing commitment reduction from $230 million to $90 million, primarily due to pending asset sales, including the sale of remaining Hugoton Basin properties expected to close in the fourth quarter of 2019. In addition to extending the facility’s term by one year, Riviera reduced its pricing grid by 50 basis points.

As of September 30, 2019, Blue Mountain had approximately $61 million drawn on its revolving credit facility, and borrowing commitments of up to $200 million with available borrowing capacity of approximately $126 million, including outstanding letters of credit, subject to covenant restrictions in the Blue Mountain Credit Facility, and approximately $21 million ending cash balance.

As of September 30, 2019 the Company had a consolidated ending cash balance of approximately $83 million. With $61 million drawn on Blue Mountain’s credit facility, the company had approximately $22 million in net cash.

Third Quarter Actuals 
Below is a summary of the Company’s consolidated third quarter results.
  Q3 2019
Actuals
Q3 2019
Actuals
Q3 2019
Actuals
  Upstream Blue Mountain Consolidated
 
Net Production (MMcfe/d) 242 242
Natural gas (MMcf/d) 194 194
Oil (Bbls/d) 2,085 2,085
NGL (Bbls/d) 5,979 5,979
 
Other revenues, net (in thousands) (1) $ 8,679 (2) $ 6,426 (3) $ 15,105 (4)
Helium revenues $ 5,120 (5) $ 5,120 (5)
Jayhawk / Other $ 3,559 $ 3,559
Blue Mountain $ 6,426 (3) $ 6,426 (3)
Costs (in thousands) $ 39,050 $ 643 $ 39,693
Lease operating expenses $ 18,307 $ 18,307
Transportation expenses $ 16,275 $ 16,275
Taxes, other than income taxes $ 4,468 $ 643 $ 5,111
 
Adjusted general and administrative expenses (Non-GAAP) (6) $ 8,612 (7) $ 3,317 (8) $ 11,929 (9)
General and administrative- severance expenses $ 2,246 $ 2,246
(in thousands)
Adjusted EBITDAX (Non-GAAP) $ 19,464 $ 1,219 (10) $ 20,683 (10)
Cash interest expense (Non-GAAP) (11) $ 1,008 $ 492 $ 1,500
Oil and natural gas capital $ 5,803 $ 5,803
Total capital $ 5,904 $ 36,590 $ 42,494
(1) Includes other revenues and margin on marketing activities
(2) Includes other revenues of approximately $5.5 million, plus marketing revenues of approximately $11.1 million, less marketing expenses of approximately $7.9 million
(3) Includes marketing revenues of approximately $34.7 million, less adjusted marketing expenses of approximately $28.3 million. Adjusted marketing expenses is a non-GAAP measure that excludes share-based compensation expenses of less than $0.1 million, and losses on derivatives of approximately $1.4 million
(4) Includes other revenues of approximately $5.5 million, plus marketing revenues of approximately $45.8 million, less adjusted marketing expenses of approximately $36.2 million. Adjusted marketing expenses is a non-GAAP measure that excludes share-based compensation expenses of less than $0.1 million, and losses on derivatives of approximately $1.4 million
(5) Includes helium revenues from the VPP Interests of approximately $3.7 million
(6) Adjusted general and administrative expenses is a non-GAAP measure that excludes share-based compensation expenses and severance expenses presented for the purpose of comparing to guidance
(7) Represents general and administrative expenses of approximately $11.4 million, excluding share-based compensation expenses of approximately $0.6 million, and severance expenses of approximately $2.2 million
(8) Represents general and administrative expenses of approximately $5.5 million, excluding share-based compensation expenses of approximately $2.2 million
(9) Represents general and administrative expenses of approximately $16.9 million, excluding share-based compensation expenses of approximately $2.8 million, and severance expenses of approximately $2.2 million
(10) Includes success fee on capital reimbursement agreement for partial sale of NW STACK gathering infrastructure to producer of approximately $1.7 million
(11) Excludes non cash amortization
Upstream Segment – Third Quarter Actuals versus Guidance
The comparison to guidance below is for the upstream assets only. The Company did not provide third quarter 2019 guidance for Blue Mountain.
  Q3 2019
Actuals
Q3 2019
Guidance
     
Net Production (MMcfe/d) 242 233 – 255
Natural gas (MMcf/d) 194 185 – 205
Oil (Bbls/d) 2,085 1,900 – 2,100
NGL (Bbls/d) 5,979 6,000 – 6,300
Other revenues, net (in thousands) (1) $ 8,679 (2) $ 7,000 – $ 9,000
Helium revenues $ 5,120 (3) $ 4,500 – $ 5,500 (3)
Jayhawk / Other $ 3,559 $ 2,500 – $ 3,500
Costs (in thousands) $ 39,050 $ 36,500 – $ 41,500
Lease operating expenses $ 18,307 $ 17,000 – $ 19,000
Transportation expenses $ 16,275 $ 16,000 – $ 17,000
Taxes, other than income taxes $ 4,468 $ 3,500 – $ 5,500
Adjusted general and administrative expenses (Non-GAAP) (4) $ 8,612 (5) $ 8,500 – $ 9,500
General and administrative- severance expenses $ 2,246 $ 1,500 – $ 2,000
Targets (Mid-Point) (in thousands)
Adjusted EBITDAX (Non-GAAP) $ 19,464 $ 19,000
Capital expenditures $ 5,904 $ 9,000
VPP Notes interest expense payments (6) $ 1,011 $ 1,000
VPP Notes principal payments $ 2,666 $ 2,700
(1) Includes other revenues and margin on marketing activities
(2) Includes other revenues of approximately $5.5 million, plus marketing revenues of approximately $11.1 million, less marketing expenses of approximately $7.9 million
(3) Includes helium revenues from the VPP Interests of approximately $3.7 million
(4) Adjusted general and administrative expenses is a non-GAAP measure that excludes share-based compensation expenses and severance expenses presented for the purpose of comparing to guidance
(5) For the three months ended September 30, 2019 represents general and administrative expenses of approximately $11.4 million, excluding share-based compensation expenses of approximately $0.6 million, and severance expenses of approximately $2.2 million
(6) Excludes non cash amortization
Upstream Segment – Fourth Quarter and Full Year 2019 Guidance
The guidance below is for the Upstream assets only. Guidance estimates have been adjusted for the sale of remaining properties located in Hugoton expected to close in the fourth quarter of 2019.
  Q4 2019E FY 2019E
Net Production (MMcfe/d) 162 – 180 238 – 243
Natural gas (MMcf/d) 133 – 147 194 – 198
Oil (Bbls/d) 1,400 – 1,600 1,655 – 1,705
NGL (Bbls/d) 3,500 – 3,900 5,650 – 5,750
Other revenues, net (in thousands) (1) $ 3,000 – $ 5,000 $ 31,000 – $ 33,000
Helium revenues $ 1,000 – $ 2,000 (2) $ 16,500 – $ 17,500 (3)
Jayhawk / Other $ 2,000 – $ 3,000 $ 14,500 – $ 15,500
Costs (in thousands) $ 25,500 – $ 29,500 $ 157,500 – $ 161,500
Lease operating expenses $ 13,500 – $ 15,500 $ 80,000 – $ 82,000
Transportation expenses $ 9,000 – $ 10,000 $ 63,000 – $ 64,000
Taxes, other than income taxes $ 3,000 – $ 4,000 $ 14,500 – $ 15,500
Adjusted general and administrative expenses (Non-GAAP) (4), (7) $ 8,500 – $ 9,500 $ 33,000 – $ 34,000
General and administrative- severance expenses $ 3,500 – $ 4,000 $ 6,000 – $ 6,500
     
Costs per Mcfe (Mid-Point) $ 1.74 $ 1.81
Lease operating expenses $ 0.92 $ 0.92
Transportation expenses $ 0.61 $ 0.72
Taxes, other than income taxes $ 0.21 $ 0.17
Targets (Mid-Point in thousands)
Adjusted EBITDAX (Non-GAAP) (7) $ 11,000 (5) $ 81,000 (6)
Capital expenditures $ 4,000 $ 66,000
VPP Notes interest expense payments $ 500 $ 2,600
VPP Notes principal payments $ 1,500 $ 6,800
Weighted Average NYMEX Differentials
Natural gas (MMBtu) ($ 0.40) – ($ 0.20) ($ 0.35) – ($ 0.30)
Oil (Bbl) ($ 2.40) – ($ 1.80) ($ 1.70) – ($ 1.30)
NGL price as a % of crude oil price 24% – 28% 28% – 32%
Unhedged Commodity Price Assumptions Oct 19 Nov 19 Dec 19 2019E
Natural gas (MMBtu) $2.43 $2.21 $2.46 $2.59
Oil (Bbl) $54.70 $54.70 $54.78 $56.47
NGL (Bbl) $14.52 $14.38 $13.76 $17.03
(1) Includes other revenues and margin on marketing activities for Upstream assets, only
(2) Includes helium revenues from the VPP Interests of approximately $1.8 million
(3) Includes helium revenues from the VPP Interests of approximately $12.8 million
(4) Excludes share-based compensation expenses and severance expenses
(5) Includes severance expenses of approximately $3.7 million
(6) Includes severance expenses of approximately $6.0 million 
(7) The Company does not provide a reconciliation of such non-GAAP financial measures to the most directly comparable GAAP financial measures on a forward-looking basis as it is unable to forecast certain items that we have defined as “Selected Items Impacting Comparability”, which items are set forth later in this press release under the heading “Non-GAAP Financial Measures and Selected Items Impacting Comparability, without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the occurrence and financial impact of and the periods in which such items may be recognized. Thus, a reconciliation of such non-GAAP financial measures to the most directly comparable GAAP financial measures could result in disclosure that could be imprecise or potentially misleading. These items could be material to and have a significant impact on the Company’s results computed in accordance with GAAP.
Hedging Update
Riviera Upstream Hedges
  2019 2020
Natural Gas Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Swaps 141 $ 2.88 30 $ 2.82
Collars 20 $ 2.75 – $3.00
Oil Volume
(Bbls/d)
Average Price
(per Bbl)
Volume
(Bbls/d)
Average Price
(per Bbl)
Swaps 1,000 $ 64.32 500 $ 64.63
Natural Gas Basis Differential positions Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Volume
(MMMBtu/d)
Average Price
(per MMBtu)
PEPL Basis Swaps 70 ($ 0.64) 20 ($ 0.45)
NWPL Basis Swaps 10 ($ 0.61) $ –
Blue Mountain Revenue Hedges
  2019 2020
Natural Gas Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Swaps 15 $ 2.81 $ –
Oil Volume
(Bbls/d)
Average Price
(per Bbl)
Volume
(Bbls/d)
Average Price
(per Bbl)
Swaps 98 $ 66.60 49 $ 55.90
Natural Gas Basis Differential positions Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Volume
(MMMBtu/d)
Average Price
(per MMBtu)
Southern Star Basis Swaps 5 ($ 0.57) $ –
Enable Basis Swaps 5 ($ 0.23) $ –
NGL positions Volume
(gallons/d in
thousands)
Average Price
(per gallon)
Volume
(gallons/d in
thousands)
Average Price
(per gallon)
Margin spreads        
Mont Belvieu propane and Conway propane 63 ($ 0.07) $ –
Mont Belvieu pentane and Conway pentane 63 ($ 0.09) $ –
Blue Mountain Cost Hedges
  2019 2020
NGL positions Volume
(gallons/d in
thousands)
Average Price
(per gallon)
Volume
(gallons/d in
thousands)
Average Price
(per gallon)
Fixed price swaps
Mont Belvieu ethane 126 $ 0.34 $ –
Mont Belvieu propane 42 $ 0.68 $ –

Earnings Call / Form 10‑Q
The Company will host a conference call Thursday, November 7, 2019 at 10:00 a.m. (Central) to discuss the Company’s third quarter 2019 results and expects to file its third quarter Form 10-Q with the Securities and Exchange Commission on or around that date. There will be prepared remarks by executive management followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing (866) 416-7462, or (409) 217-8223 for international calls using Conference ID: 6994895. Interested parties may also listen over the internet at www.rivieraresourcesinc.com. A replay of the call will be available on the Company’s website.

Supplemental information can be found at the following link on our website: http://ir.rivieraresourcesinc.com/events-and-presentations

ABOUT RIVIERA RESOURCES
Riviera Resources, Inc. is an independent oil and natural gas company with a strategic focus on efficiently operating its mature low-decline assets, developing its growth-oriented assets, and returning capital to its stockholders. Riviera’s properties are located in East Texas, North Louisiana, the Uinta Basin and Mid-Continent regions. Riviera also owns Blue Mountain Midstream LLC, a midstream company centered in the core of the Merge play in the Anadarko Basin.

Non-GAAP Financial Measures and Selected Items Impacting Comparability
To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are earnings before interest, taxes, depreciation and amortization, exploration costs, noncash gains and losses on commodity derivatives, accrued settlements on commodity derivative contracts related to current production period, share-based compensation expenses, gains and losses on asset sales and other, reorganization items, and asset impairments (“Adjusted EBITDAX”) and earnings before interest, taxes, depreciation and amortization, noncash gains and losses on commodity derivatives, accrued settlements on commodity derivative contracts related to current production period, share-based compensation expenses, gains and losses on asset sales and other, and asset impairments (“Adjusted EBITDA”). Management believes these non-GAAP financial measures provide useful information to investors because these non-GAAP measures, when viewed with the Company’s GAAP results and accompanying reconciliations, provide a more complete understanding of the Company’s performance than GAAP results alone.

Forward-Looking Statements
Statements made in this press release that are not historical facts are “forward-looking statements.” These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. These statements include, among others, statements regarding our 2019 guidance, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, our strategic objectives with respect to Blue Mountain Midstream, our financial position, business strategy and other plans and objectives for future operations. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to the Company’s financial and operational performance and results, low or declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves, the capacity and utilization of midstream facilities and the regulatory environment. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read “Risk Factors” in the Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. The Company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events.

CONTACT:
Investor Relations
(281) 840-4168
[email protected]

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
    September 30, 2019     December 31, 2018  
    (in thousands, except share amounts)
ASSETS  
Current assets:  
Cash and cash equivalents $ 83,161 $ 18,529
Accounts receivable – trade, net 67,156 114,489
Derivative instruments 14,132 10,758
Restricted cash 45,757 31,248
Other current assets 12,699 26,721
Assets held for sale 419,290 38,396
Total current assets 642,195 240,141
Noncurrent assets:  
Oil and natural gas properties (successful efforts method) 316,973 756,552
Less accumulated depletion and amortization (64,796 ) (93,507 )
252,177 663,045
Other property and equipment 461,847 606,244
Less accumulated depreciation (54,991 ) (62,368 )
406,856 543,876
Derivative instruments 1,243 4,603
Deferred income taxes 129,091
Other noncurrent assets 9,376 12,078
10,619 145,772
Total noncurrent assets 669,652 1,352,693
Total assets $ 1,311,847 $ 1,592,834
LIABILITIES AND EQUITY  
Current liabilities:  
Accounts payable and accrued expenses $ 104,726 $ 159,228
Derivative instruments 4,087 4,719
Other accrued liabilities 48,122 34,474
Liabilities held for sale 127,023 3,725
Total current liabilities 283,958 202,146
Noncurrent liabilities:  
Credit facilities 61,100 24,500
Asset retirement obligations 52,143 103,814
Other noncurrent liabilities 13,210
Total noncurrent liabilities 126,453 128,314
Commitments and contingencies (Note 10)
Equity:  
Preferred Stock ($0.01 par value, 30,000,000 shares authorized; no shares issued at September 30, 2019, or December 31, 2018)  
Common Stock ($0.01 par value, 270,000,000 shares authorized; 58,632,328 shares and 69,197,284 shares issued at September 30, 2019, and December 31, 2018, respectively)   586 692
Additional paid-in capital   1,115,483 1,256,730
Retained earnings   (214,633 ) 4,952
Total equity 901,436 1,262,374
Total liabilities and equity $ 1,311,847 $ 1,592,834
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
    2019     2018     2019     2018  
    (in thousands, except per share amounts)
Revenues and other:    
Oil, natural gas and natural gas liquids sales $ 51,029 $ 89,653 $ 194,131 $ 313,533
Gains (losses) on commodity derivatives 5,665 (3,175 ) 12,673 (25,730 )
Marketing revenues 45,828 67,246 166,569 156,480
Other revenues 5,532 5,877 16,685 18,158
108,054 159,601 390,058 462,441
Expenses:    
Lease operating expenses 18,307 22,930 66,204 94,902
Transportation expenses 16,275 22,304 53,478 62,611
Marketing expenses 37,688 63,149 132,888 145,231
General and administrative expenses 16,954 90,931 49,434 228,105
Exploration costs 1,947 2,487 4,154 3,742
Depreciation, depletion and amortization 20,060 21,515 65,013 71,960
Impairment of assets held for sale 95,080 113,470
Taxes, other than income taxes 5,111 7,162 14,010 22,729
(Gains) losses on sale of assets and other, net (7,587 ) 221 (24,967 ) (208,009 )
203,835 230,699 473,684 421,271
Other income and (expenses):    
Interest expense, net of amounts capitalized (2,329 ) (594 ) (5,403 ) (1,582 )
Other, net (595 ) 105 (708 ) 473
(2,924 ) (489 ) (6,111 ) (1,109 )
Reorganization items, net (284 ) (1,277 ) (756 ) (4,487 )
(Loss) income from continuing operations before income taxes (98,989 ) (72,864 ) (90,493 ) 35,574
Income tax expense (benefit) 126,646 (39,628 ) 129,092 25,247
(Loss) income from continuing operations (225,635 ) (33,236 ) (219,585 ) 10,327
(Loss) income from discontinued operations, net of income taxes (14,899 ) 19,674
Net (loss) income   $ (225,635 ) $ (48,135 )   $ (219,585 ) $ 30,001
Income (loss) per share:    
(Loss) income from continuing operations per share ‒ Basic $ (3.76 ) $ (0.43 )   $ (3.40 ) $ 0.13
(Loss) income from continuing operations per share ‒ Diluted $ (3.76 ) $ (0.43 )   $ (3.40 ) $ 0.13
 
(Loss) income from discontinued operations per share ‒ Basic $ $ (0.20 )   $ $ 0.26
(Loss) income from discontinued operations per share ‒ Diluted $ $ (0.20 ) $ $ 0.26
Net (loss) income per share ‒ Basic $ (3.76 ) $ (0.63 ) $ (3.40 ) $ 0.39
Net (loss) income per share ‒ Diluted $ (3.76 ) $ (0.63 ) $ (3.40 ) $ 0.39
Weighted average shares outstanding ‒ Basic   60,004 76,135 64,576 76,171
Weighted average shares outstanding ‒ Diluted   60,004 76,135   64,576 76,518
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
    Nine Months Ended
September 30,
 
    2019     2018  
(in thousands)
Cash flow from operating activities:  
Net (loss) income $ (219,585 ) $ 30,001
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Income from discontinued operations (19,674 )
Depreciation, depletion and amortization 65,013 71,960
Impairment of assets held for sale 113,470
Deferred income taxes 129,092 25,382
Total (gains) losses on derivatives, net (6,386 ) 25,730
Cash settlements on derivatives 5,740 (25,341 )
Share-based compensation expenses 10,624 16,105
Gains on sale of assets and other, net (27,366 ) (204,644 )
Other 8,897 1,336
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net 37,305 57,674
Decrease in other assets 5,367 61,309
Decrease in accounts payable and accrued expenses (29,997 ) (51,608 )
Decrease in other liabilities (4,331 ) (15,750 )
Net cash provided by (used in) operating activities 87,843 (27,520 )
Cash flow from investing activities:  
Acquisition of property, plant and equipment (3,380 )
Development of oil and natural gas properties (67,864 ) (56,116 )
Purchases of other property and equipment (82,232 ) (116,237 )
Proceeds from sale of properties and equipment and other 177,907 367,086
Net cash provided by investing activities — continuing operations 24,431 194,733
Net cash provided by investing activities — discontinued operations 7,000
Net cash provided by investing activities 24,431 201,733
Cash flow from financing activities:
Net transfers to Parent (481,449 )
Repurchases of shares (143,097 ) (7,576 )
Proceeds from borrowings 142,825
Repayments of debt (29,615 )
Debt issuance costs paid (3,246 ) (2,505 )
Distributions to unitholders (18,717 )
Other (841 )
Net cash used in financing activities (33,133 ) (511,088 )
Net increase (decrease) in cash, cash equivalents and restricted cash 79,141 (336,875 )
Cash, cash equivalents and restricted cash:
Beginning 49,777 520,922
Ending $ 128,918 $ 184,047

Adjusted EBITDAX (Non-GAAP Measure)

The non-GAAP financial measure of Adjusted EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX is a measure used by Company management to evaluate the Company’s operational performance and for comparisons to the Company’s industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

The following presents a reconciliation of net income (loss) to Adjusted EBITDAX:
    Three Months Ended
September 30,
  Nine Months Ended
September 30,
    2019   2018   2019   2018
    (in thousands)
Net (loss) income $ (225,635 ) $ (48,135 ) $ (219,585 ) $ 30,001
Plus (less):
Loss (income) from discontinued operations 14,899 (19,674 )
Interest expense, net of amounts capitalized 2,329 594 5,403 1,582
Income tax expense (benefit) 126,646 (39,628 ) 129,092 25,247
Depreciation, depletion and amortization   20,060 21,515   65,013 71,960
Exploration costs 1,947 2,487 4,154 3,742
EBITDAX     (74,653 )     (48,268 )     (15,923 )     112,858
Plus (less):
Noncash losses (gains) on commodity derivatives 3,738 2,869 (478 ) 20,360
Accrued settlements on commodity derivative contracts related to current production period (1) (154 ) (124 ) (1,182 ) 1,444
Share-based compensation expenses 2,832 56,063 12,819 131,288
(Gains) losses on sale of assets and other, net (2)  (6,444 ) 23 (25,230 ) (207,237 )
Reorganization items, net (3) 284 1,277 756 4,487
Impairment of assets held for sale 95,080 113,470
Adjusted EBITDAX (4)   $ 20,683   $ 11,840   $ 84,232   $ 63,200
(1) Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.
(2) Primarily represent gains or losses on the sale of assets, earnings from equity method investments, gains or losses on inventory valuation, and write-off of deferred financing fees.
(3) Represent costs and income directly associated with the predecessor’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.
(4) Includes success fee on capital reimbursement agreement of approximately $2 million for both the three months and nine months ended September 30, 2019.

Adjusted EBITDAX and Adjusted EBITDA (Non-GAAP Measures)

The non-GAAP financial measures of Adjusted EBITDAX and adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP. Adjusted EBITDAX and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP.

Adjusted EBITDAX and Adjusted EBITDA are measures used by Company management to evaluate the Company’s operational performance and for comparisons to the Company’s industry peers. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

The following presents a reconciliation of net income (loss) to Adjusted EBITDAX and Adjusted EBITDA:
      Three Months Ended September 30, 2019
      (in thousands)
      Consolidated   Upstream   Blue Mountain
 
Net loss   $ (225,635 ) $ (222,365 ) $ (3,270 )
Plus (less):
Interest expense 2,329 1,711 618
Income tax expense 126,646 126,646
Depreciation, depletion and amortization 20,060 17,593 2,467
EBITDA     (76,600 )     (76,415 )     (185 )
Exploration costs 1,947 1,947
EBITDAX     (74,653 )     (74,468 )     (185 )
Plus (less):
Noncash losses (gains) on commodity derivatives 3,738 4,629 (891 )
Accrued settlements on commodity derivative contracts related to current production period (1) (154 ) (68 ) (86 )
Share-based compensation expenses 2,832 623 2,209
(Gains) losses on sale of assets and other, net (2) (6,444 ) (6,616 ) 172
Reorganization items, net (3) 284 284
Impairment of assets held for sale 95,080 95,080
Adjusted EBITDAX / Adjusted EBITDA (4)   $ 20,683   $ 19,464   $ 1,219
      Nine Months Ended September 30, 2019
      (in thousands)
      Consolidated   Upstream   Blue Mountain
 
Net loss   $ (219,585 ) $ (213,878 ) $ (5,707 )
Plus (less):
Interest expense 5,403 4,170 1,233
Income tax expense 129,092 129,092
Depreciation, depletion and amortization 65,013 58,122 6,891
EBITDA     (20,077 )   (22,494 )     2,417
Exploration costs 4,154 4,154
EBITDAX     (15,923 )   (18,340 )     2,417
Plus (less):
Noncash (gains) losses on commodity derivatives (478 ) (4,036 ) 3,558
Accrued settlements on commodity derivative contracts related to current production period (1) (1,182 ) (17 ) (1,165 )
Share-based compensation expenses 12,819 4,623 8,196
(Gains) losses on sale of assets and other, net (2) (25,230 ) (26,211 ) 981
Reorganization items, net (3) 756 756
Impairment of assets held for sale 113,470 113,470
Adjusted EBITDAX / Adjusted EBITDA (4)   $ 84,232   70,245   $ 13,987
(1) Represent amounts related to commodity derivative contracts that settled during the respective period (contract terms had expired) but cash had not been received as of the end of the period.
(2) Primarily represent gains or losses on the sale of assets, earnings from equity method investments, gains or losses on inventory valuation, and write-off of deferred financing fees.
(3) Represent costs and income directly associated with the predecessor’s filing for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code since the petition date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.
(4) Consolidated and Blue Mountain include success fee on capital reimbursement agreement of approximately $2 million for both the three months and nine months ended September 30, 2019.


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